The present disclosure is directed to systems and methods for treating crude oil, intermediate refining streams, and refining products to substantially reduce the content of undesired heteroatoms, specifically sulfur, nitrogen, nickel, vanadium, iron and reduce the total acid number and to do so utilizing equipment that has a relatively low capital investment and is economical to operate.
Systems and methods for removing oxidized-heteroatom contaminants including, but not limited to, sulfur, nitrogen, nickel, vanadium, iron and reduce the total acid number of liquid hydrocarbon feed streams are disclosed. After subjecting a liquid hydrocarbon stream to oxidation conditions, thereby oxidizing at least a portion of the heteroatom compounds (e.g., oxidizing dibenzothiophenes to sulfones), the oxidized heteroatom compounds are reacted with caustic (e.g., sodium hydroxide, potassium hydroxide, eutectic mixtures thereof etc.) and a selectivity promoter to produce substantially lower heteroatom-containing hydrocarbon products.
As is well known in the industry, crude oil contains heteroatoms such as sulfur, nitrogen, nickel, vanadium and acidic oxygenates in quantities that negatively impact the refinery processing of the crude oil fractions. Light crude oils or condensates contain heteroatoms in concentrations as low as 0.001 Wt %. In contrast, heavy crude oils contain heteroatoms as high as 5-7 Wt %. The heteroatom content of crude oil increases with increasing boiling point and the heteroatom content increases with decreasing API gravity. These impurities must be removed during refining operations to meet the environmental regulations for the final product specifications (e.g., gasoline, diesel, fuel oil) or to prevent the contaminants from decreasing catalyst activity, selectivity, and lifetime in downstream refining operations. Contaminants such as sulfur, nitrogen, trace metals, and total acid number (TAN) in the crude oil fractions negatively impact these downstream processes, and others, including hydrotreating, hydrocracking and FCC to name just a few. These contaminants are present in the crude oil fractions in varying structures and concentrations.
It is widely recognized that the emission of sulfur oxides from fossil fuel combustion causes a serious atmospheric pollution problem. Indeed, the sulfur is converted through combustion into various sulfur oxides that can be transformed into acids, thus, it is believed, SOx emissions contribute to the formation of acid rain and also to the reduction of the efficiency of catalytic converters in automobiles. Furthermore, sulfur compounds are thought to ultimately increase the particulate content of combustion products.
A variety of methods have been proposed for removing sulfur compounds either from fuels before combustion or from emission gases afterward. Most refineries employ hydrodesulfurization (HDS) as the predominant process for removing sulfur from hydrocarbon streams. HDS remains a cost-effective option for light streams with sulfur levels up to about 2% (w/w) elemental sulfur. But the environmental benefits of HDS are offset in very heavy and sour (>2% elemental sulfur) streams because the energy input to the reaction, the high pressures and the amount of hydrogen necessary to remove the sulfur paradoxically create a substantial CO2 emission problem.
Because of these issues, reduction of contaminants and, in particular, of the sulfur content in hydrocarbon streams has become a major objective of environmental legislation worldwide. Pending sulfur regulations in the United States for on-road diesel will be 15 ppm in NRLM diesel fuel. As of October 2012, on road diesel sulfur specifications are 15 ppm for NRLM diesel fuel. In the European Union that specification has tightened to 10 ppm in January 2011 for diesels intended for inland waterways and for on-road and off-road diesel operated equipment. In China, the on-road diesel specification are 10 ppm as of 2012. Currently Japan, also has on-road diesel specification of 10 ppm.
Refiners typically use catalytic hydrodesulfurizing (“HDS”, commonly referred to as “hydrotreating”) methods to lower the sulfur content of hydrocarbon fuels. In HDS, a hydrocarbon stream that is derived from a petroleum distillation is treated in a reactor that operates at temperatures ranging between 575 and 750° F. (about 300 to about 400° C.), a hydrogen pressure that ranges between 430 to 14,500 psi (3000 to 10,000 kPa or 30 to 100 atmospheres) and hourly space velocities ranging between 0.5 and 4 h−1. Dibenzothiophenes in the feed react with the hydrogen when in contact with a catalyst arranged in a fixed bed that comprises metal sulfides from groups VI and VIII (e.g., cobalt and molybdenum sulfides or nickel and molybdenum sulfides) supported on alumina. Because of the operating conditions and the use of hydrogen, these methods can be costly both in capital investment and operating costs.
As is currently known, HDS or hydrotreating may provide a treated product in compliance with the current strict sulfur level targets. However, due to the presence of sterically hindered refractory sulfur compounds such as unsubstituted and substituted dibenzothiophenes, the process is not without issues. For example, it is particularly difficult to eliminate traces of sulfur using such catalytic processes when the sulfur is contained in molecules such as dibenzothiophene with alkyl substituents in position 4, or 4 and 6. Attempts to completely convert these species, which are more prevalent in heavier stocks such as diesel fuel and fuel oil, have resulted in increased equipment costs, more frequent catalyst replacements, degradation of product quality due to side reactions, and continued inability to comply with the strictest sulfur requirements for some feeds.
This has prompted many to pursue non-hydrogen alternatives to desulfurization, such as oxydesulfurization. One attempt at solving the thiophene problem discussed above includes selectively desulfurizing dibenzothiophenes contained in the hydrocarbon stream by oxidizing the dibenzothiophenes into a sulfone in the presence of an oxidizing agent, followed by optionally separating the sulfone compounds from the rest of the hydrocarbon stream. Oxidation has been found to be beneficial because oxidized sulfur compounds can be removed using a variety of separation processes that rely on the altered chemical properties such as the solubility, volatility, and reactivity of the sulfone compounds. One specific sulfoxidation method and system is disclosed in International Publication Number WO 2009/120238 A1, to Litz et al., the disclosure of which is hereby incorporated by reference to the extent not inconsistent with the present disclosure.
One issue with sulfoxidation lies in the disposal of the sulfones. If the sulfones are hydrotreated, they may be converted back to the original dibenzothiophene compounds thereby regenerating the original problem. The feed sulfur content may be likely to be in the range of 0% to 10% weight sulfur. Sulfur, on average, comprises about 15 wt % of substituted and unsubstituted dibenzothiophene molecules. Therefore, up to 67 wt % of the oil may be removed as sulfone extract. For a typical refinery processing 40,000 barrels per day of crude oil, up to 27,000 barrels per day of sulfone oil will be generated, which is believed to be too much to dispose conventionally as a waste product. Further, the disposal of sulfone oil also wastes valuable hydrocarbons, which could theoretically be recycled if an efficient process were available.
As stated above, the primary challenge presented to oxydesulfurization remains the removal of the SOx from the sulfone and sulfoxide groups created by oxidation of the initial organic sulfur species. Kocal et al., U.S. Pat. No. 7,790,021 B2, the disclosure of which is hereby incorporated by reference to the extent not inconsistent with the present disclosure, teach the use of an aqueous caustic stream and a caustic waste stream to treat the sulfones and sulfoxide streams to produce substituted biphenyls. The problem with the disclosed method is the costly extra steps to remove the substituted biphenyl products from the aqueous caustic stream and the lack of selectivity towards unsubstituted biphenyls, and the lack of teaching any effect on other heteroatom-containing species.
A similar teaching of the use of molten caustic was disclosed by Aida et al (reference) to treat the sulfones in oxidized coal. Aida's teaching gives rise to ionizable and non-ionizable biphenyls with no apparent selectivity to product formation. Aida later teaches (Tetrahedron Letters publication) that desulfonylation with caustic alkoxide ions proceeds with predominant formation of carbon oxygen bond formation but still substantive formation of hydroxybiphenyls which are extremely challenging to separate from the caustic stream because they are ionizable.
Garcia et al (J. Mol Catalysis 2008) teach a desulfonylation reaction catalyzed by nickel compounds. Aida and Kocal et al. showed that caustics react with sulfones, but their methods do not show selectivity to unsubstituted products and has not been shown capable of removing other heteroatoms. Garcia et al. show that there is a way to selectively make unsubstituted biphenyls from sulfones, but fail do so in a cost effective manner and they do not demonstrate the capability of removing other heteroatoms. The method unfortunately employs an expensive stoichiometric Grignard reagent to selectively form unsubstituted biphenyl products and is therefore unsuited to commercial fuel treatment for economic reasons.
Documents and references believed relevant to the present disclosure follow:
Reaction of Dibenzothiophene Sulfone with Alkoxides Aida, T.; Squires, T. G.; Venier, C. G. Tetrahedron Letters, (1983), 24(34) p 3543-3546
Development of an efficient coal-desulfurization process: oxy-alkalinolysis Authors Aida, T.; Venier, C. G.; Squires, T. G. Publication Date 1982 Sep. 1 Technical Report Resource Conference: American Chemical Society symposium on coal liquefaction, pages 328-334 Kansas City, Mo., USA, 1 Sep. 1982 Ames Lab., Iowa (USA); Advanced Fuel Research, Inc., East Hartford, Conn. (USA) Deoxydesulfurization of Sulfones Derived from Dibenzothiophene using Nickel Compounds, Authors: Alberto Oviedo, Jorge Torres-Nieto, Alma Arevalo, and Juventino J. Garcia. J. Mol. Catalysis A: Chemical, (2008) 293, p 65-71.
It has long been known that various metallic elements are found in naturally occurring and synthetic crude oils (see O. I. Miller et al, Anal. Chem., 24, 1728 [1952]).
Some of these metal impurities are known to be harmful when present in charge stocks for petroleum refining, for example cracking, when present in fuels for boilers and turbines and the like uses.
A process for removing vanadium and sodium from a crude oil is disclosed in U.S. Pat. No. 2,764,525 (F. W. Porter et al) wherein the oil is contacted in the presence of hydrogen with alumina containing a minor amount of ferric oxide.
A method of treating petroleum oil containing trace metal components is disclosed in U.S. Pat. No. 2,910,434 (H. V. Hess, et al) wherein the oil is contacted with an inert packing material in the presence of hydrogen gas.
In U.S. Pat. No. 2,987,470 (M. Turken) a process is disclosed for demineralizing oil by contact thereof in an ebullated bed with particulate contact materials, for example bauxite, alumina and the like.
In U.S. Pat. No. 3,819,509 (R. H. Walk et al) metal- and sulfur-containing contaminants in a residual oil are removed from the oil by contacting the oil in the presence of desulfurization catalyst and an intimate admixture of inert demetallization solids.
In U.S. Pat. No. 3,964,995 (R. H. Walk et al) metals are removed from sulfur- and metals-contaminated oil using porous alumina solids activated with an oxide promoter of the group Fe2O3, TiO2 and SiO2.
In U.S. Pat. No. 4,192,736 (Kluksdahl) metals are removed from oil by contact with alumina containing a phosphorous oxide promoter.
In U.S. Pat. No. 4,645,589 (F. J. Krambeck et al) metals are removed from oil by aqueous phase extraction with a phosphorous compound.
A process for removing metals and coke precursors is disclosed in U.S. Pat. No. 6,245,223 (M. L. Gorbaty et al) wherein the oil is contacted with a solid, low surface area adsorbent.
Therefore, there is a need for a selective process for removing heteroatoms (including, but not limited to, sulfur, nitrogen, nickel, vanadium, iron and the like) from an oxidized-heteroatom-containing hydrocarbon stream thereby avoiding the need of expensive reagents, waste disposal, and other separation and handling as well as cost issues associated with the waste streams.